Integrated desulfurization and denitrification process including mild hydrotreating and oxidation of aromatic-rich hydrotreated products

ABSTRACT

Reduction of sulfur-containing and nitrogen-containing compounds from hydrocarbon feeds is achieved by first contacting the entire feed with a hydrotreating catalyst in a hydrotreating reaction zone operating under mild conditions to convert the labile organosulfur and organonitrogen compounds. An extraction zone downstream of the hydrotreating reaction zone separates an aromatic-rich fraction that contains a substantial amount of the remaining refractory organosulfur and organonitrogen compounds. The aromatic-lean fraction is substantially free of organosulfur and organonitrogen compounds, since the non-aromatic organosulfur and organonitrogen compounds were the labile organosulfur and organonitrogen compounds which were initially removed by mild hydrotreating. The aromatic-rich fraction is oxidized to convert the refractory organosulfur and organonitrogen compounds to oxidized sulfur-containing and nitrogen-containing hydrocarbon compounds. These oxidized organosulfur and organonitrogen compounds are subsequently removed.

RELATED APPLICATIONS

Not applicable

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to integrated oxidation processes toefficiently reduce the sulfur and nitrogen content of hydrocarbons toproduce fuels having reduced sulfur and nitrogen levels.

2. Description of Related Art

The discharge into the atmosphere of sulfur compounds during processingand end-use of the petroleum products derived from sulfur-containingsour crude oil pose health and environmental problems. The stringentreduced-sulfur specifications applicable to transportation and otherfuel products have impacted the refining industry, and it is necessaryfor refiners to make capital investments to greatly reduce the sulfurcontent in gas oils to 10 parts per million by weight (ppmw), or less.In industrialized nations such as the United States, Japan and thecountries of the European Union, refineries for transportation fuel havealready been required to produce environmentally clean transportationfuels. For instance, in 2007 the United States Environmental ProtectionAgency required the sulfur content of highway diesel fuel to be reduced97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfurdiesel). The European Union has enacted even more stringent standards,requiring diesel and gasoline fuels sold in 2009 to contain less than 10ppmw of sulfur. Other countries are following in the direction of theUnited States and the European Union and are moving forward withregulations that will require refineries to produce transportation fuelswith an ultra-low sulfur level.

To keep pace with recent trends toward production of ultra-low sulfurfuels, refiners must choose among the processes or crude oils thatprovide flexibility to ensure that future specifications are met withminimum additional capital investment, in many instances by utilizingexisting equipment. Conventional technologies such as hydrocracking andtwo-stage hydrotreating offer solutions to refiners for the productionof clean transportation fuels. These technologies are available and canbe applied as new grassroots production facilities are constructed.However, many existing hydroprocessing facilities, such as those usingrelatively low pressure hydrotreaters were constructed before these morestringent sulfur reduction requirements were enacted and represent asubstantial prior investment. It is very difficult to upgrade existinghydrotreating reactors in these facilities because of the comparativelymore severe operational requirements (i.e., higher temperature andpressure conditions) to obtain clean fuel production. Availableretrofitting options for refiners include elevation of the hydrogenpartial pressure by increasing the recycle gas quality, utilization ofmore active catalyst compositions, installation of improved reactorcomponents to enhance liquid-solid contact, the increase of reactorvolume, and the increase of the feedstock quality.

There are many hydrotreating units installed worldwide producingtransportation fuels containing 500-3000 ppmw sulfur. These units weredesigned for, and are being operated at, relatively mild conditions,i.e., low hydrogen partial pressures of 30 kilograms per squarecentimeter for straight run gas oils boiling in the range of from 180°C. to 370° C.

However, with the increasing prevalence of more stringent environmentalsulfur specifications in transportation fuels mentioned above, themaximum allowable sulfur levels are being reduced to no greater than 15ppmw, and in some cases no greater than 10 ppmw. This ultra-low level ofsulfur in the end product typically requires either construction of newhigh pressure hydrotreating units, or a substantial retrofitting ofexisting facilities, e.g., by integrating new reactors, incorporatinggas purification systems, reengineering the internal configuration andcomponents of reactors, and/or deployment of more active catalystcompositions. Each of these options represents a substantial capitalinvestment

Sulfur-containing compounds that are typically present in hydrocarbonfuels include aliphatic molecules such as sulfides, disulfides andmercaptans, as well as aromatic molecules such as thiophene,benzothiophene and its alkylated derivatives, and dibenzothiophene andits alkyl derivatives such as 4,6-dimethyl-dibenzothiophene. Aromaticsulfur-containing molecules have a higher boiling point than aliphaticsulfur-containing molecules, and are consequently more abundant inhigher boiling fractions.

In addition, certain fractions of gas oils possess different properties.The following table illustrates the properties of light and heavy gasoils derived from Arabian Light crude oil:

TABLE 1 Feedstock Name Light Heavy Blending Ratio — — API Gravity ° 37.530.5 Carbon wt % 85.99 85.89 Hydrogen wt % 13.07 12.62 Sulfur wt % 0.951.65 Nitrogen ppmw 42 225 ASTM D86 Distillation IBP/5 V % ° C. 189/228147/244 10/30 V % ° C. 232/258 276/321 50/70 V % ° C. 276/296 349/37385/90 V % ° C. 319/330 392/398 95 V % ° C. 347 Sulfur SpeciationOrganosulfur Compounds ppmw 4591 3923 Boiling Below 310° C.Dibenzothiophenes ppmw 1041 2256 C₁-Dibenzothiophenes ppmw 1441 2239C₂-Dibenzothiophenes ppmw 1325 2712 C₃-Dibenzothiophenes ppmw 1104 5370

As set forth above in Table 1, the light and heavy gas oil fractionshave ASTM D86 85 V % points of 319° C. and 392° C., respectively.Further, the light gas oil fraction contains less sulfur and nitrogenthan the heavy gas oil fraction (0.95 wt % sulfur as compared to 1.65 wt% sulfur and 42 ppmw nitrogen as compared to 225 ppmw nitrogen).

Advanced analytical techniques such as multi-dimensional gaschromatography with a sulfur chemiluminescence detector as described byHua, et al. (Hua R., et al., “Determination of sulfur-containingcompounds in diesel oils by comprehensive two-dimensional gaschromatography with a sulfur chemiluminescence detector,” Journal ofChromatography A, Volume 1019, Issues 1-2, Nov. 26, 2003, Pages 101-109)have shown that the middle distillate cut boiling in the range of170-400° C. contains sulfur species including thiols, sulfides,disulfides, thiophenes, benzothiophenes, dibenzothiophenes, andbenzonaphthothiophenes, with and without alkyl substituents.

The sulfur speciation and content of light and heavy gas oils areconventionally analyzed by two methods. In the first method, sulfurspecies are categorized based on structural groups. The structuralgroups include one group having sulfur-containing compounds boiling atless than 310° C., including dibenzothiophenes and its alkylatedisomers, and another group including 1-, 2- and 3-methyl-substituteddibenzothiophenes, denoted as C₁, C₂ and C₃, respectively. Based on thismethod, the heavy gas oil fraction contains more alkylateddi-benzothiophene molecules than the light gas oils.

In the second method of analyzing sulfur content of hydrocarbons, andreferring to FIG. 1A, the cumulative sulfur concentrations are plottedagainst the boiling points of the sulfur-containing compounds to observeconcentration variations and trends. Note that the boiling pointsdepicted are those of detected sulfur-containing compounds, rather thanthe boiling point of the total hydrocarbon mixture. The boiling point ofseveral refractory sulfur-containing compounds includingdibenzothiophene, 4-methyldibenzothiophene and4,6-dimethyldibenzothiophene are also shown in FIG. 1A for convenience.The cumulative sulfur specification curves show that the aromaticportion contains a higher proportion of heavier sulfur-containingcompounds and a lower proportion of lighter sulfur-containing compoundsas compared to the fraction containing primarily paraffins andnaphthenes.

Aliphatic sulfur-containing compounds are more easily desulfurized(labile) using conventional hydrodesulfurization methods. However,certain highly branched aromatic molecules can sterically hinder thesulfur atom removal and are moderately more difficult (refractory) todesulfurize using conventional hydrodesulfurization methods.

Among the sulfur-containing aromatic compounds, thiophenes andbenzothiophenes are relatively easy to hydrodesulfurize. The addition ofalkyl groups to the ring compounds increases the difficulty ofhydrodesulfurization. Dibenzothiophenes resulting from addition ofanother aromatic ring to the benzothiophene family are even moredifficult to desulfurize, and the difficulty varies greatly according totheir alkyl substitution, with di-beta substitution being the mostdifficult to desulfurize, thus justifying their “refractory”appellation. These beta substituents hinder exposure of the heteroatomto the active site on the catalyst.

The economical removal of refractory sulfur-containing compounds istherefore exceedingly difficult to achieve, and accordingly removal ofsulfur-containing compounds in hydrocarbon fuels to an ultra-low sulfurlevel is very costly utilizing current hydrotreating techniques. Whenprevious regulations permitted sulfur levels up to 500 ppmw, there waslittle need or incentive to desulfurize beyond the capabilities ofconventional hydrodesulfurization, and hence the refractorysulfur-containing compounds were not targeted. However, in order to meetthe more stringent sulfur specifications, these refractorysulfur-containing compounds must be substantially removed fromhydrocarbon fuels streams.

The relative reactivity of thiols and sulfides are much higher thanthose of aromatic sulfur compounds, as indicated in a study published inSong, Chunshan, “An overview of new approaches to deep desulfurizationfor ultra-clean gasoline, diesel fuel and jet fuel” Catalysis Today, 86(2003), pp. 211-263. Mercaptan/thiols and sulfides are much morereactive than the aromatic sulfur compounds. It should be noted thatnon-thiophenic sulfides such as paraffinic and/or naphthenic are presentin diesel range hydrocarbons as seen from the chromatograph of FIG. 1B.

The development of non-conventional processes for desulfurization ofpetroleum distillate feedstocks has been widely studied, and certainconventional approaches are based on oxidation of sulfur-containingcompounds described, e.g., in U.S. Pat. Nos. 5,910,440, 5,824,207,5,753,102, 3,341,448 and 2,749,284.

Oxidation processes for heteroatomic compounds, such as oxidativedesulfurization is attractive for several reasons. First, relativelymild reaction conditions, e.g., temperature from room temperature up to200° C. and pressure from 1 up to 15 atmospheres, can often be used,thereby resulting a priori in reasonable investment and operationalcosts, especially compared to hydrogen consumption in hydroprocessingtechniques which is usually expensive. Another attractive aspect of theoxidative process is related to the reactivity of aromaticsulfur-containing species. This is evident since the high electrondensity at the sulfur atom caused by the attached electron-rich aromaticrings, which is further increased with the presence of additional alkylgroups on the aromatic rings, will favor its electrophilic attack asshown in Table 2 (Otsuki, S. et al., “Oxidative desulfurization of lightgas oil and vacuum gas oil by oxidation and solvent extraction,” EnergyFuels 14:1232-1239 (2000)). Moreover, the intrinsic reactivity ofmolecules such as 4,6-DMBT is substantially higher than that of DBT,which is much easier to desulfurize by hydrodesulfurization.

TABLE 2 Electron Density of selected sulfur species Sulfur Electron K(L/ compound Formulas Density (mol.min)) Thiophenol

5.902 0.270 Methyl Phenyl Sulfide

5.915 0.295 Diphenyl Sulfide

5.860 0.156 4,6-DMDBT

5.760 0.0767 4-MDBT

5.759 0.0627 Dibenzo- thiophene

5.758 0.0460 Benzo- thiophene

5.739 0.00574 2,5- Dimethyl- thiophene

5.716 — 2-methyl- thiophene

5.706 — Thiophene

5.696 —

Certain existing desulfurization processes incorporate bothhydrodesulfurization and oxidative desulfurization. For instance,Cabrera et al. U.S. Pat. No. 6,171,478 describes an integrated processin which the hydrocarbon feedstock is first contacted with ahydrodesulfurization catalyst in a hydrodesulfurization reaction zone toreduce the content of certain sulfur-containing molecules. The resultinghydrocarbon stream is then sent in its entirety to an oxidation zonecontaining an oxidizing agent where residual sulfur-containing compoundsare converted into oxidized sulfur-containing compounds. Afterdecomposing the residual oxidizing agent, the oxidized sulfur-containingcompounds are solvent extracted, resulting in a stream of oxidizedsulfur-containing compounds and a reduced-sulfur hydrocarbon oil stream.A final step of adsorption is carried out on the latter stream tofurther reduce the sulfur level.

Kocal U.S. Pat. No. 6,277,271 also discloses a desulfurization processintegrating hydrodesulfurization and oxidative desulfurization. A streamcomposed of sulfur-containing hydrocarbons and a recycle streamcontaining oxidized sulfur-containing compounds is introduced in ahydrodesulfurization reaction zone and contacted with ahydrodesulfurization catalyst. The resulting hydrocarbon streamcontaining a reduced sulfur level is contacted in its entirety with anoxidizing agent in an oxidation reaction zone to convert the residualsulfur-containing compounds into oxidized sulfur-containing compounds.The oxidized sulfur-containing compounds are removed in one stream and asecond stream of hydrocarbons having a reduced concentration of oxidizedsulfur-containing compounds is recovered. Like the process in Cabrera etal., the entire hydrodesulfurized effluent is subjected to oxidation inthe Kocal process.

Wittenbrink et al. U.S. Pat. No. 6,087,544 discloses a desulfurizationprocess in which a distillate feedstream is first fractionated into alight fraction containing from about 50 to 100 ppm of sulfur, and aheavy fraction. The light fraction is passed to a hydrodesulfurizationreaction zone. Part of the desulfurized light fraction is then blendedwith half of the heavy fraction to produce a low sulfur distillate fuel.However, not all of the distillate feedstream is recovered to obtain thelow sulfur distillate fuel product, resulting in a substantial loss ofhigh quality product yield.

Rappas et al. PCT Publication WO02/18518 discloses a two-stagedesulfurization process located downstream of a hydrotreater. Afterhaving been hydrotreated in a hydrodesulfurization reaction zone, theentire distillate feedstream is introduced to an oxidation reaction zoneto undergo biphasic oxidation in an aqueous solution of formic acid andhydrogen peroxide. Thiophenic sulfur-containing compounds are convertedto corresponding sulfones. Some of the sulfones are retained in theaqueous solution during the oxidation reaction, and must be removed by asubsequent phase separation step. The oil phase containing the remainingsulfones is subjected to a liquid-liquid extraction step. In the processof WO02/18518, like Cabrera et al. and Kocal, the entirehydrodesulfurized effluent is subject to oxidation reactions, in thiscase biphasic oxidation.

Levy et al. PCT Publication WO03/014266 discloses a desulfurizationprocess in which a hydrocarbon stream having sulfur-containing compoundsis first introduced to an oxidation reaction zone. Sulfur-containingcompounds are oxidized into the corresponding sulfones using an aqueousoxidizing agent. After separating the aqueous oxidizing agent from thehydrocarbon phase, the resulting hydrocarbon stream is passed to ahydrodesulfurization step. In the process of WO03/014266, the entireeffluent of the oxidation reaction zone is subject tohydrodesulfurization.

Gong et al. U.S. Pat. No. 6,827,845 discloses a three-step process forremoval of sulfur- and nitrogen-containing compounds in a hydrocarbonfeedstock. All or a portion of the feedstock is a product of ahydrotreating process. In the first step, the feed is introduced to anoxidation reaction zone containing peracid that is free of catalyticallyactive metals. Next, the oxidized hydrocarbons are separated from theacetic acid phase containing oxidized sulfur and nitrogen compounds. Inthis reference, a portion of the stream is subject to oxidation. Thehighest cut point identified is 316° C. In addition, this referenceexplicitly avoids catalytically active metals in the oxidation zone,which necessitates an increased quantity of peracid and more severeoperating conditions. For instance, the H₂O₂:S molar ratio in one of theexamples is 640, which is extremely high as compared to oxidativedesulfurization with a catalytic system.

Gong et al. U.S. Pat. No. 7,252,756 discloses a process for reducing theamount of sulfur- and/or nitrogen-containing compounds for refineryblending of transportation fuels. A hydrocarbon feedstock is contactedwith an immiscible phase containing hydrogen peroxide and acetic acid inan oxidation zone. After a gravity phase separation, the oxidizedimpurities are extracted with aqueous acetic acid. A hydrocarbon streamhaving reduced impurities is recovered, and the acetic acid phaseeffluents from the oxidation and the extraction zones are passed to acommon separation zone for recovery of the acetic acid. In an optionalembodiment of U.S. Pat. No. 7,252,756, the feedstock to the oxidationprocess can be a low-boiling component of a hydrotreated distillate.This reference contemplates subjecting the low boiling fraction to theoxidation zone.

None of the above-mentioned references describe a suitable andcost-effective process for desulfurization of hydrocarbon fuel fractionswith specific sub-processes and apparatus for targeting differentorganosulfur compounds. In particular, conventional methods do notseparate a hydrocarbon fuel stream into fractions containing differentclasses of sulfur-containing compounds with different reactivitiesrelative to the conditions of hydrodesulfurization and oxidativedesulfurization. Conventionally, most approaches subject the entire gasoil stream to the oxidation reactions, requiring unit operations thatmust be appropriately dimensioned to accommodate the full process flow.

Aromatic extraction is an established process used at certain stages ofvarious refinery and other petroleum-related operations. In certainexisting processes, it is desirable to remove aromatics from the endproduct, e.g., lube oils and certain fuels, e.g., diesel fuel. In otherprocesses, aromatics are extracted to produce aromatic-rich products,for instance, for use in various chemical processes and as an octanebooster for gasoline.

U.S. Pat. No. 5,021,143 discloses a process in which a feed isfractionated into a light naphtha, a medium naphtha and a heavy naphtha.Aromatics are extracted from the heavy naphtha fraction using aselective liquid solvent, and the aromatic-lean raffinate is mixed withthe kerosene or diesel pool. The aromatic-rich extract is regenerated bycontacting with light petrol so as to produce an aromatic-rich petrolproduct.

U.S. Pat. No. 4,359,596 discloses a process in which aromatics areextracted from hydrocarbon mixtures such as isomerization processstreams, catalytic cracking naphthas, and lube stocks. Liquid salts,such as quaternary phosphonium and ammonium salts of halides, acids ormore complex anions are used as extraction liquids.

U.S. Pat. Nos. 4,592,832, 4,909,927, 5,110,445 5,880,325 and 6,866,772disclose various processes for upgrading lube oils. In particular, theseprocesses use various solvents to extract aromatics.

With the steady increase in demand for hydrocarbon fuels having anultra-low sulfur level, a need exists for an efficient and effectiveprocess and apparatus for desulfurization. As far as the presentinventors are aware, it has not previously been suggested to combinewell-established aromatic extraction technology with desulfurization ofhydrocarbon fuels, and in particular with integrated desulfurizationincluding hydrotreating and oxidative desulfurization.

Accordingly, it is an object of the present invention to desulfurize anddenitrify a hydrocarbon fuel stream containing different classes ofsulfur-containing and nitrogen-containing compounds having differentreactivities utilizing reactions separately directed to labile andrefractory classes of sulfur-containing and nitrogen-containingcompounds.

It is a further object of the present invention to produce hydrocarbonfuels having reduced sulfur and nitrogen levels by removal of labileorganosulfur and organonitrogen compounds in a feedstream usinghydrotreating under relatively mild conditions followed by targetedremoval of refractory organosulfur and organonitrogen compounds usingoxidation.

As used herein, the term “labile organosulfur compounds” meansorganosulfur compounds that can be easily desulfurized under relativelymild hydrotreating pressure and temperature conditions, and the term“refractory organosulfur compounds” means organosulfur compounds thatare relatively more difficult to desulfurize under mild hydrotreatingconditions. Likewise, the term “labile organonitrogen compounds” meansorganonitrogen compounds that can be easily denitrified under relativelymild hydrotreating pressure and temperature conditions, and the term“refractory organonitrogen compounds” means organonitrogen compoundsthat are relatively more difficult to denitrify under mild hydrotreatingconditions.

Additionally, as used herein, the terms “mild hydrotreating” and “mildoperating conditions” (when used in reference to hydrotreating) meanshydrotreating processes operating at temperatures of 400° C. and below,hydrogen partial pressures of 40 bars and below, and hydrogen feed ratesof 500 liters per liter of oil, and below.

SUMMARY OF THE INVENTION

The above objects and further advantages are provided by the apparatusand process of the invention for removal of undesired aromatic andnon-aromatic organosulfur and organonitrogen compounds, both refractoryand labile, which utilizes mild hydrotreating of a fuel stream to removelabile organosulfur and organonitrogen compounds and oxidation of anaromatic-rich fraction of the hydrotreated intermediate product toremove refractory organosulfur and organonitrogen compounds.

According to the present invention, a cost-effective apparatus andprocess for reduction of sulfur and nitrogen levels of hydrocarbonstreams includes integration of hydrotreating with an oxidation reactionzone, in which the hydrocarbon sulfur-containing compounds are convertedby oxidation to compounds containing sulfur and oxygen, such assulfoxides or sulfones, and the hydrocarbon nitrogen-containingcompounds are converted by oxidation to compounds containing nitrogenand oxygen. The oxidized sulfur-containing and nitrogen-containingcompounds have different chemical and physical properties, whichfacilitate their removal from the balance of the hydrocarbon stream.Oxidized sulfur-containing and nitrogen-containing compounds can beremoved by extraction, distillation and/or adsorption.

The present invention comprehends an integrated system and process thatis capable of efficiently and cost-effectively reducing the organosulfurand organonitrogen content of hydrocarbon fuels. The cost ofhydrotreating is minimized by operating under relatively mildtemperature and pressure conditions conforming to the capabilities ofexisting prior art hydrotreating apparatus and systems. For instance,deep desulfurization of hydrocarbon fuels according to the presentinvention effectively optimizes use of integrated apparatus andprocesses, combining mild hydrotreating (such as hydrodesulfurization)and oxidation (such as oxidative desulfurization). Most importantly,using the apparatus and process of the present invention, refiners canadapt existing hydrotreating equipment and run such equipment under mildoperating conditions. Accordingly, hydrocarbon fuels are economicallydesulfurized and denitrified to very low levels.

Deep desulfurization and denitrification of hydrocarbon feedstreams isachieved by first contacting the entire fuel stream with a catalyst,such as a hydrodesulfurization catalyst, in a hydrotreating reactionzone operating at mild conditions to convert labile organosulfur andorganonitrogen compounds. An aromatic separation zone downstream of thehydrotreating reaction zone separates the hydrotreated effluent toobtain a first fraction, which is a relatively aromatic-lean fraction,and a second fraction, which is a relatively aromatic-rich fraction.

Since aromatic extraction operations typically do not provide sharpcut-offs between the aromatics and non-aromatics, the aromatic-leanfraction contains a major proportion of the non-aromatic content of theinitial feed and a minor proportion of the aromatic content of theinitial feed, and the aromatic-rich fraction contains a major proportionof the aromatic content of the initial feed and a minor proportion ofthe non-aromatic content of the initial feed. The amount ofnon-aromatics in the aromatic-rich fraction, and the amount of aromaticsin the aromatic-lean fraction, depend on various factors as will beapparent to one of ordinary skill in the art, including the type ofextraction and the number of theoretical plates in the extractor, thetype of solvent and the solvent ratio.

The aromatic compounds that pass to the aromatic-rich fraction includearomatic organo sulfur compounds, such as benzothiophene,dibenzothiophene, benzonaphtenothiophene, and derivatives ofbenzothiophene, dibenzothiophene and benzonaphtenothiophene. Variousnon-aromatic organosulfur compounds that may have been present in theinitial feed, i.e., prior to hydrotreating, include mercaptans, sulfidesand disulfides.

In addition, certain organonitrogen compounds having aromatic moietiesalso pass with the aromatic-rich fraction. Further, certain organicnitrogen compounds, paraffinic or naphthenic nature, may have polaritiescausing them to be extracted and remain in aromatic-rich fraction.

As used herein, the term “major proportion of the non-aromaticcompounds” means at least greater than 50 wt % of the non-aromaticcontent of the feed to the extraction zone, preferably at least greaterthan about 85 wt %, and most preferably greater than at least about 95wt %. Also as used herein, the term “minor proportion of thenon-aromatic compounds” means no more than 50 wt % of the feed to theextraction zone, preferably no more than about 15 wt %, and mostpreferably no more than about 5 wt %.

Also as used herein, the term “major proportion of the aromaticcompounds” means at least greater than 50 wt % of the aromatic contentof the feed to the extraction zone, preferably at least greater thanabout 85 wt %, and most preferably greater than at least about 95 wt %.Also as used herein, the term “minor proportion of the non-aromaticcompounds” means no more than 50 wt % of the feed to the extractionzone, preferably no more than about 15 wt %, and most preferably no morethan about 5 wt %.

The aromatic-rich fraction contains a majority of the remainingrefractory organosulfur compounds, including4,6-dimethyldibenzothiophene and its derivatives. The aromatic-leanfraction is substantially free of organosulfur compounds, since thenon-aromatic organosulfur and organonitrogen compounds are mainly labileorganosulfur compounds which were removed in the mild hydrotreatingstep. The aromatic-rich fraction is contacted with an oxidizing agentand an active metal catalyst in an oxidation reaction zone to convertthe refractory organosulfur and organonitrogen compounds into oxidizedorganosulfur and organonitrogen compounds. These oxidized organosulfurand organonitrogen compounds are subsequently removed, by extractionand, optionally, by adsorption, to produce a hydrocarbon product streamthat contains a reduced level of organosulfur and organonitrogencompounds, or sent to different product pools, depending on the refineryrequirements. The two streams, i.e., the effluent from the hydrotreatingreaction zone and the effluent from the oxidation reaction zone, can becombined to provide a hydrocarbon product containing a reduced level oforganosulfur and organonitrogen compounds. Alternatively, the twostreams can be separately maintained, for instance, if aromaticextraction is contemplated in downstream refinery operations for otherpurposes.

The inclusion of an aromatic separation zone in an integrated system andprocess combining hydrotreating and oxidativedesulfurization/denitrification allows a partition of the differentclasses of sulfur-containing and nitrogen-containing compounds accordingto their respective reactivity factors, thereby optimizing utilizationof the different types of heteroatom removal processes and henceresulting in a more cost effective process. The volumetric/mass flowthrough the oxidation reaction zone is reduced, since only thearomatic-rich fraction of the original feedstream containing refractorysulfur-containing and nitrogen-containing compounds is subjected to theoxidation process. As a result, the requisite equipment capacity, andaccordingly both the capital equipment cost and the operating costs, areminimized. In addition, the total hydrocarbon stream is not subjected tooxidation reactions, thus avoiding unnecessary oxidation of organosulfurand organonitrogen compounds that are otherwise handled using mildhydrotreating, which also minimizes the extraction and adsorptioncapacity needed to remove these oxidized organosulfur and organonitrogencompounds.

Furthermore, product quality is improved by the integrated process ofthe present invention since undesired side reactions that would resultfrom oxidation of the entire feedstream under generally harsh conditionsare avoided.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing summary, as well as the following detailed description ofpreferred embodiments of the invention will be best understood when readin conjunction with the attached drawings. For the purpose ofillustrating the invention, there are shown in the drawings embodimentswhich are presently preferred. It should be understood, however, thatthe invention is not limited to the precise arrangements and apparatusshown. In the drawings, the same numeral is used to refer to the same orsimilar elements, in which:

FIG. 1A is a graph showing cumulative sulfur concentrations plottedagainst boiling points indicating the boiling points ofsulfur-containing aromatic compounds;

FIG. 1B is a graphic representation of the relative reactivities ofvarious compounds in the hydrodesulfur process with the increase in sizeof the sulfur-containing molecule;

FIG. 2 is a schematic diagram of an integrated system and process of thepresent invention that includes an aromatic extraction zone between ahydrotreating zone and an oxidation zone;

FIG. 3 is a schematic diagram of a separation apparatus for removingoxidized organosulfur and organonitrogen compounds from an aromatic-richportion of the hydrotreated products according to the system and processof the present invention; and

FIGS. 4-9 show various examples of apparatus suitable for use as thearomatic extraction zone.

DETAILED DESCRIPTION OF THE INVENTION

The present invention comprehends an integrated process to producehydrocarbon fuels with reduced levels of organosulfur and organonitrogencompounds. The process includes the following steps:

a. contacting the hydrocarbon stream in its entirety with ahydrotreating catalyst in a hydrotreating reaction zone under mildoperating conditions;

b. subjecting the effluent hydrotreated stream to an aromatic extractionzone to obtain a first fraction and a second fraction;

c. the first, generally aromatic-lean, fraction, is substantially freeof organosulfur and organonitrogen compounds since the labileorganosulfur and organonitrogen compounds were converted during thehydrotreating step;

d. the organosulfur compounds in the second, generally aromatic-rich,fraction are primarily refractory organosulfur compounds, includingbenzothiophenes e.g., long chain alkylated benzothiophenes,dibenzothiophenes and alkyl derivatives, e.g.,4,6-dimethyldibenzothiophene, and the organonitrogen compounds in thesecond, generally aromatic-rich, fraction are primarily refractoryorganonitrogen compounds; this second fraction is contacted with anoxidizing agent and a metal catalyst in an oxidation reaction zone toconvert the organosulfur compounds into oxidized sulfur-containingcompounds and to convert organonitrogen into oxidizednitrogen-containing compounds; and

e. the oxidized sulfur-containing and nitrogen-containing compounds aresubsequently removed in a separation zone, by oxidation product removalprocesses and apparatus that include extraction, distillation,adsorption, or combined processes comprising one or more of extraction,distillation and adsorption.

Referring now to FIG. 2, an integrated desulfurization anddenitrification apparatus 12 according to the present invention isschematically illustrated. Apparatus 12 generally includes ahydrotreating reaction zone 18, an extraction zone 22, an oxidation zone44 and a separation zone 48. Hydrocarbon feedstock 14 is mixed with ahydrogen stream 16 and is introduced to the hydrotreating reaction zone18 and into contact with a hydrotreating catalyst under mild operatingconditions. Extraction zone 22 is an aromatic extraction unit, examplesof which are described in more detail below. The hydrocarbon stream 14is preferably a middle distillate boiling in the range of about 180° C.to about 400° C., typically containing up to about 3 wt % sulfur,although one of ordinary skill in the art will appreciate that otherhydrocarbon streams can benefit from the practice of the system andmethod of the present invention. The hydrotreating catalyst can be, forinstance, an alumina base containing cobalt and molybdenum, as is knownin hydrodesulfurization operations.

As will be understood by one of ordinary skill in the art, “mild”operating conditions is relative and the range of operating conditionsdepend on the feedstock being processed. According to the presentinvention, these mild operating conditions as used in conjunction withhydrotreating a mid-distillate stream, i.e., boiling in the range ofabout 180° C. to about 370° C., include: a temperature of about 300° C.to about 400° C., and preferably about 320° C. to about 380° C.; areaction pressure of about 20 bars to about 100 bars, and preferablyabout 30 bars to about 60 bars; a hydrogen partial pressure of belowabout 55 bars, and preferably about 25 bars to about 40 bars; a feedrate of about 0.5 hr⁻¹ to about 10 hr⁻¹, and preferably about 1.0 hr⁻¹to about 4 hr⁻¹; and a hydrogen feed rate in certain embodiments ofabout 100 liters of hydrogen per liter of oil (L/L) to about 500 L/L, infurther embodiments about 100 L/L to about 300 L/L, and in additionalembodiments about 100 L/L to about 200 L/L.

The resulting hydrodesulfurized hydrocarbon stream 20 is substantiallyfree of unconverted labile organosulfur compounds including aliphaticsulfur-containing compounds and thiophenes, benzothiophenes and theirderivatives, and is substantially free of unconverted labileorganonitrogen compounds. This stream 20 is passed to the aromaticextraction zone 22 to separate a first, aromatic-lean, fraction asraffinate stream 28 from a second, generally aromatic-rich, fraction asextract stream 36. Extraction zone 22 can be any suitable aromaticextraction apparatus operating on the basis of solvent extraction. Asolvent feed 24 is introduced into the aromatic extraction zone 22.Various non-limiting examples of apparatus suitable for the aromaticextraction zone 22 are described in further detail below.

Stream 28 contains a major proportion of the non-aromatic content of theinitial feed, which now has a reduced level of organosulfur andorganonitrogen compounds, and a minor proportion of the aromatic contentof the initial feed. In addition, extraction solvent can also exist instream 28, e.g., in the range of about 0 wt % to about 15 wt % (based onthe total amount of stream 28), preferably less than about 8 wt %. Inoperations in which the solvent existing in stream 28 exceeds a desiredor predetermined amount, solvent may be removed from the hydrocarbonproduct, for example, using a flashing or stripping unit 30 or othersuitable apparatus. The essentially solvent-free, low sulfur content andlow nitrogen content hydrocarbon product 32 can be recovered separatelyor in combination with the fraction 52 that has been subjected tooxidation zone 44 and separated in the separation zone 48. Solvent 34from the flashing or stripping unit 30 can be recycled to the aromaticextraction zone 22, e.g., via a surge drum 26. Initial solvent feed ormake-up solvent can be introduced via stream 27.

Stream 36 from the aromatic extraction zone 22 generally includes amajor proportion of the aromatic content of the initial feedstock and aminor proportion of the non-aromatic content of the initial feedstock.This aromatic content includes aromatic organosulfur compounds such asthiophene, benzothiophene and its long chain alkylated derivatives, anddibenzothiophene and its alkyl derivatives such as4,6-dimethyl-dibenzothiophene, benzonaphtenothiophene and its alkylderivatives. Further, the aromatic-rich stream includes aromaticorganonitrogen compounds such as acridine, 1-methyl-1-H-indole,quinoline, and their derivatives.

In addition, extraction solvent can also exist in stream 36, e.g., inthe range of about 70 wt % to about 98 wt % (based on the total amountof stream 36), preferably less than about 85 wt %. In operations inwhich the solvent existing in stream 36 exceeds a desired orpredetermined amount, solvent can be removed from the hydrocarbonproduct, for example, using a flashing unit 38 or other suitableapparatus. Solvent 42 from the flashing unit 38 can be recycled to theextraction zone 22, e.g., via a surge drum 26. The essentiallysolvent-free and aromatic-rich hydrocarbon product 40 is passed to theoxidation zone 44 to be contacted with an oxidizing agent and one ormore catalytically active metals. The oxidizing agent can be an aqueousoxidant such as hydrogen peroxide, organic peroxides such as ter-butylhydroperoxide, or peroxo acids, a gaseous oxidant such as oxides ofnitrogen (e.g., nitrous oxide), oxygen, air, ozone, or combinationscomprising any of these oxidants. The oxidation catalyst can be selectedfrom one or more homogeneous or heterogeneous catalysts having metalsfrom Group IVB to Group VIIIB of the Periodic Table, including Mn, Co,Fe, Cr and Mo.

The aromatic-rich fraction, the oxidizing agent and the oxidationcatalyst are maintained in contact for a period of time that issufficient to complete the oxidation reactions, generally from about 5to about 180 minutes, in certain embodiments about 15 to about 90minutes and in further embodiments about 15 minutes to about 30 minutes.The reaction conditions of the oxidation zone 44 include: an operatingpressure of about 1 bar to about 30 bars, in certain embodiments about 1bar to about 10 bars and in further embodiments at about 1 bar to about3 bars; and an operating temperature of about 20° C. to about 300° C.,in certain embodiments about 20° C. to about 150° C. and in furtherembodiments about 45° C. to about 60° C. The molar feed ratio ofoxidizing agent to sulfur is generally about 1:1 to about 100:1, incertain embodiments about 1:1 to about 30:1, and in further embodimentsabout 1:1 to about 4:1. In oxidation zone 44, at least a substantialportion of the aromatic sulfur-containing compounds and theirderivatives contained in the aromatic-rich fraction are converted tooxidized sulfur-containing compounds, i.e., sulfones and sulfoxides, andoxidized nitrogen-containing compounds, and discharged as oxidizedhydrocarbon stream 46.

Stream 46 from the oxidation zone 44 is conveyed to the separation zone48 to remove the oxidized compounds as discharge stream 50 and obtain ahydrocarbon stream 52 that contains a reduced level of sulfur,preferably an ultra-low level of sulfur, i.e., less than 15 ppmw, and areduced level of nitrogen. Streams 32 and 52 can be combined to providea hydrocarbon product 41 that contains an ultra-low level of sulfur.Alternatively, the two streams 32 and 52 can be separately maintained.

Stream 50 from the separation zone 48 can be passed to a sulfones andsulfoxides handling unit (not shown) to recover hydrocarbons free ofsulfur, for example, by cracking reactions, thereby increasing the totalhydrocarbon product yield. Alternatively, stream 50 can be passed toother refining processes such as coking or solvent deasphalting.

Referring to FIG. 3, one embodiment of a process for removing oxidessuch as sulfoxides and sulfones contained in effluent from oxidationzone 44 is shown, although alternative processes for removing sulfoxidesand sulfones can be employed. Stream 46 containing oxidizedhydrocarbons, water and catalyst is introduced into a decanting vessel54 to decant water and catalyst as discharge stream 56 and separate ahydrocarbon mixture stream 58. Stream 56 which can include a mixture ofwater (e.g., from the aqueous oxidant), any remaining oxidant andsoluble catalyst, is withdrawn from the decanting vessel 54 and can berecycled to the oxidation zone 44 (not shown in FIG. 3), and thehydrocarbon stream 58 is passed to the separation zone 48. Thehydrocarbon stream 58 is introduced into one end of a counter-currentextractor 60, and a solvent stream 62 is introduced into the oppositeend. Oxidized sulfur-containing and/or nitrogen-containing compounds areextracted from the hydrocarbon stream with the solvent as solvent-richextract stream 64.

The solvent stream 62 can include a selective solvent such as methanol,acetonitrile, any polar solvent having a Hildebrandt value of at least19, and combinations comprising at least one of the foregoing solvents.Acetonitrile and methanol are preferred solvents for the extraction dueto their polarity, volatility, and low cost. The efficiency of theseparation between the sulfones and/or sulfoxides can be optimized byselecting solvents having desirable properties including, but notlimited to boiling point, freezing point, viscosity, and surfacetension.

The raffinate 66 is introduced into an adsorption column 68 where it iscontacted with an adsorbent material such as an alumina adsorbent toproduce the finished hydrocarbon product stream 52 that has an ultra-lowlevel of sulfur, which is recovered. The solvent-rich extract 64 fromthe extractor 60 is introduced into a distillation column 70 for solventrecovery via the overhead recycle stream 72, and the oxidizedsulfur-containing and/or nitrogen-containing compounds, includingsulfones and/or sulfoxides, are discharged as stream 50.

The extraction zone 22 can be any suitable solvent extraction apparatuscapable of partitioning the effluent 20 from the hydrodesulfurizationzone into a generally aromatic-lean stream 28 and a generallyaromatic-rich stream 36. Selection of solvent, operating conditions, andthe mechanism of contacting the solvent and effluent 20 permit controlover the level of aromatic extraction. For instance, suitable solventsinclude furfural, N-methyl-2-pyrrolidone, dimethylformamide ordimethylsulfoxide, and can be provided in a solvent to oil ratio ofabout 20:1, in certain embodiments about 4:1, and in further embodimentsabout 1:1. The aromatic extraction unit 22 can operate at a temperaturein the range of about 20° C. to about 120° C., and in certainembodiments in the range of about 40° C. to about 80° C. The operatingpressure of the aromatic extraction unit 22 can be in the range of about1 bar to about 10 bars, and in certain embodiments, in the range ofabout 1 bar to 3 bars. Types of apparatus useful as unit 22 of thepresent invention include stage-type extractors or differentialextractors.

An example of a stage-type extractor is a mixer-settler apparatus 404schematically illustrated in FIG. 4. Mixer-settler apparatus 404includes a vertical tank 442 incorporating a turbine or a propelleragitator 444 and one or more baffles 446. Charging inlets 448, 450 arelocated at the top of tank 442 and outlet 454 is located at the bottomof tank 442. The feedstock to be extracted is charged into vessel 442via inlet 448 and a suitable quantity of solvent is added via inlet 450.The agitator 444 is activated for a period of time sufficient to causeintimate mixing of the solvent and charge stock, and at the conclusionof a mixing cycle, agitation is halted and, by control of a valve 456,at least a portion of the contents are discharged and passed to asettler 458. The phases separate in the settler 458 and a raffinatephase containing an aromatic-lean hydrocarbon mixture and an extractphase containing an aromatic-rich mixture are withdrawn via outlets 462and 464, respectively. In general, a mixer-settler apparatus can be usedin batch mode, or a plurality of mixer-settler apparatus can be stagedto operate in a continuous mode.

Another stage-type extractor is a centrifugal contactor. Centrifugalcontactors are high-speed, rotary machines characterized by relativelylow residence time. The number of stages in a centrifugal device isusually one, however, centrifugal contactors with multiple stages canalso be used. Centrifugal contactors utilize mechanical devices toagitate the mixture to increase the interfacial area and decrease themass transfer resistance.

Various types of differential extractors (also known as “continuouscontact extractors,”) that are also suitable for use as unit 22 of thepresent invention include, but are not limited to, centrifugalcontactors and contacting columns such as tray columns, spray columns,packed towers, rotating disc contactors and pulse columns.

Contacting columns are suitable for various liquid-liquid extractionoperations. Packing, trays, spray or other droplet-formation mechanismsor other apparatus are used to increase the surface area in which thetwo liquid phases (i.e., a solvent phase and a hydrocarbon phase)contact, which also increases the effective length of the flow path. Incolumn extractors, the phase with the lower viscosity is typicallyselected as the continuous phase, which, in the case of aromaticextraction unit 22, is the solvent phase. In certain embodiments, thephase with the higher flow rate can be dispersed to create moreinterfacial area and turbulence. This is accomplished by selecting anappropriate material of construction with the desired wettingcharacteristics. In general, aqueous phases wet metal surfaces andorganic phases wet non-metallic surfaces. Changes in flows and physicalproperties along the length of an extractor can also be considered inselecting the type of extractor and/or the specific configuration,materials or construction, and packing material type and characteristics(i.e., average particle size, shape, density, surface area, and thelike).

A tray column 504 is schematically illustrated in FIG. 5. A light liquidinlet 550 at the bottom of column 504 receives liquid hydrocarbon, and aheavy liquid inlet 552 at the top of column 504 receives liquid solvent.Column 504 includes a plurality of trays 544 and associated downcomers546. A top level baffle 547 physically separates incoming solvent fromthe liquid hydrocarbon that has been subjected to prior extractionstages in the column 504. Tray column 504 is a multi-stagecounter-current contactor. Axial mixing of the continuous solvent phaseoccurs at region 548 between trays 544, and dispersion occurs at eachtray 544 resulting in effective mass transfer of solute into the solventphase. Trays 544 can be sieve plates having perforations ranging fromabout 1.5 to 4.5 mm in diameter and can be spaced apart by about 150-600mm.

Light hydrocarbon liquid passes through the perforation in each tray 544and emerges in the form of fine droplets. The fine hydrocarbon dropletsrise through the continuous solvent phase and coalesce into an interfacelayer 558 and are again dispersed through the tray 544 above. Solventpasses across each plate and flows downward from tray 544 above to thetray 544 below via downcomer 546. The principle interface 560 ismaintained at the top of column 504. Aromatic-lean hydrocarbon liquid isremoved from outlet 554 at the top of column 504 and aromatic-richsolvent liquid is discharged through outlet 556 at the bottom of column504. Tray columns are efficient solvent transfer apparatus and havedesirable liquid handling capacity and extraction efficiency,particularly for systems of low-interfacial tension.

An additional type of unit operation suitable for extracting aromaticsfrom the hydrocarbon feed is a packed bed column. FIG. 6 is a schematicillustration of a packed bed column 604 having a hydrocarbon inlet 650and a solvent inlet 652. A packing region 646 is provided upon a supportplate 644. Packing region 646 comprises suitable packing materialincluding, but not limited to, Pall rings, Raschig rings, Kascade rings,Intalox saddles, Berl saddles, super Intalox saddles, super Berlsaddles, Demister pads, mist eliminators, telerrettes, carbon graphiterandom packing, other types of saddles, and the like, includingcombinations of one or more of these packing materials. The packingmaterial is selected so that it is fully wetted by the continuoussolvent phase. The solvent introduced via inlet 652 at a level above thetop of the packing region 646 flows downward and wets the packingmaterial and fills a large portion of void space in the packing region646. Remaining void space is filled with droplets of the hydrocarbonliquid which rise through the continuous solvent phase and coalesce toform the liquid-liquid interface 660 at the top of the packed bed column604. Aromatic-lean hydrocarbon liquid is removed from outlet 654 at thetop of column 604 and aromatic-rich solvent liquid is discharged throughoutlet 656 at the bottom of column 604. Packing material provides largeinterfacial areas for phase contacting, causing the droplets to coalesceand reform. The mass transfer rate in packed towers can be relativelyhigh because the packing material lowers the recirculation of thecontinuous phase.

Further types of apparatus suitable for aromatic extraction in thesystem and method of the present invention include rotating disccontactors. FIG. 7 is a schematic illustration of a rotating disccontactor 704 known as a Scheiebel® column commercially available fromKoch Modular Process Systems, LLC of Paramus, N.J., USA. It will beappreciated by those of ordinary skill in the art that other types ofrotating disc contactors can be implemented as an aromatic extractionunit included in the system and method of the present invention,including but not limited to Oldshue-Rushton columns, and Kuhniextractors. The rotating disc contactor is a mechanically agitated,counter-current extractor. Agitation is provided by a rotating discmechanism, which typically runs at much higher speeds than a turbinetype impeller as described with respect to FIG. 4.

Rotating disc contactor 704 includes a hydrocarbon inlet 750 toward thebottom of the column and a solvent inlet 752 proximate the top of thecolumn, and is divided into number of compartments formed by a series ofinner stator rings 742 and outer stator rings 744. Each compartmentcontains a centrally located, horizontal rotor disc 746 connected to arotating shaft 748 that creates a high degree of turbulence inside thecolumn. The diameter of the rotor disc 746 is slightly less than theopening in the inner stator rings 742. Typically, the disc diameter is33-66% of the column diameter. The disc disperses the liquid and forcesit outward toward the vessel wall 762 where the outer stator rings 744create quiet zones where the two phases can separate. Aromatic-leanhydrocarbon liquid is removed from outlet 754 at the top of column 704and aromatic-rich solvent liquid is discharged through outlet 756 at thebottom of column 704. Rotating disc contactors advantageously providerelatively high efficiency and capacity and have relatively lowoperating costs.

An additional type of apparatus suitable for aromatic extraction in thesystem and method of the present invention is a pulse column. FIG. 8 isa schematic illustration of a pulse column system 804, which includes acolumn with a plurality of packing or sieve plates 844, a light phase,i.e., solvent, inlet 850, a heavy phase, i.e., hydrocarbon feed, inlet852, a light phase outlet 854 and a heavy phase outlet 856.

In general, pulse column system 804 is a vertical column with a largenumber of sieve plates 844 lacking down corners. The perforations in thesieve plates 844 typically are smaller than those of non-pulsatingcolumns, e.g., about 1.5 mm to about 3.0 mm in diameter.

A pulse-producing device 870, such as a reciprocating pump, pulses thecontents of the column at frequent intervals. The rapid reciprocatingmotion, of relatively small amplitude, is superimposed on the usual flowof the liquid phases. Bellows or diaphragms formed of coated steel(e.g., coated with polytetrafluoroethylene), or any other reciprocating,pulsating mechanism can be used. A pulse amplitude of 5-25 mm isgenerally recommended with a frequency of 100-260 cycles per minute. Thepulsation causes the light liquid (solvent) to be dispersed into theheavy phase (oil) on the upward stroke and heavy liquid phase to jetinto the light phase on the downward stroke. The column has no movingparts, low axial mixing, and high extraction efficiency.

A pulse column typically requires less than a third the number oftheoretical stages as compared to a non-pulsating column. A specifictype of reciprocating mechanism is used in a Karr Column which is shownin FIG. 9.

The addition of an aromatic extraction zone into the apparatus andprocess of the invention that integrates a hydrotreating zone and anoxidation zone uses low cost units in both zones as well as morefavorable conditions in the hydrotreating zone, i.e., milder pressureand temperature and reduced hydrogen consumption. Only the aromatic-richfraction is oxidized to convert the refractory sulfur-containing andnitrogen-containing compounds. This results in more cost-effectivedesulfurization and denitrification of hydrocarbon fuels, particularlyremoval of the refractory sulfur-containing and nitrogen-containingcompounds, thereby efficiently and economically producing fuel productshaving reduced sulfur and nitrogen content.

The present invention offers distinct advantages when compared toconventional processes for deep desulfurization of hydrocarbon fuel. Forexample, in certain conventional approaches to deep desulfurization, theentire hydrocarbon stream undergoes both hydrodesulfurization andoxidative desulfurization, requiring reactors of high capacity for bothprocesses. Furthermore, the high operating costs and undesired sidereactions that can negatively effect certain desired fuelcharacteristics are avoided using the process and apparatus of thepresent invention. In addition, operating costs associated with theremoval of the oxidized sulfur-containing compounds from the entirefeedstream are decreased as only a portion of the initial feed issubjected to oxidative desulfurization.

EXAMPLE

A straight run (SR) gas oil was hydrotreated in a fixed bed reactor at30 Kg/cm2 hydrogen partial pressure, 340° C., a liquid hourly spacevelocity of 1.44 h⁻¹ and at a hydrogen to oil ratio of 280Liters/Liters. The properties of the SR gas oil are given in Table 3.The sulfur content of the gas oil was reduced from 13,000 ppmw to 662ppmw.

TABLE 3 SR Gas Hydrotreated Property Unit Method Oil Product Density @15.6° C. Kg/Lt ASTM D4052 0.850 0.850 Sulfur wt % ASTM D4294 1.3 0.0662Nitrogen ppmw 178 91 Aromatics wt % 31.5 29.5 Paraffins and wt % 68.570.5 Naphthenes Distillation ASTM D2892 IBP ° C. 52 53  5 wt % ° C. 186187  10 wt % ° C. 215 213  30 wt % ° C. 267 262  50 wt % ° C. 304 299 70 wt % ° C. 344 338  90 wt % ° C. 403 397  95 wt % ° C. 426 420 100 wt% ° C. 466 463

The hydrotreated gas oil was then passed to a counter-current aromaticextraction unit to separate the products into an aromatic-rich fractionand an aromatic-lean fraction. The extractor was operated at 60° C.,atmospheric pressure and at a solvent-to-diesel ratio of 1.1/1.0 usingfurfural as solvent.

The aromatic-lean fraction yield was 68 wt % and contained 61 ppmw ofsulfur and 10.5 wt % aromatics, and was passed to a diesel pool. Thearomatic rich fraction yield was 32 wt % and contained 80 wt % aromaticsand 600 ppmw of sulfur.

The aromatic rich fraction was oxidized at 75° C. under atmosphericpressure for 2 hours using hydrogen peroxide as oxidant at a ratio ofH₂O₂/S of 10, and using 0.5 wt % sodium tungsten as a catalyst alongwith acetic acid. The oxidation by-products, mostly sulfones, wereremoved by an extraction and adsorption step. The final aromaticfraction, which contained less than 10 ppmw of sulfur after oxidation,extraction and adsorption steps, was then sent to the diesel pool andcombined with the aromatic-lean fraction. The final gas oil fractioncontained less than 50 ppmw of sulfur.

The method and apparatus of the present invention have been describedabove and in the attached drawings; however, modifications will beapparent to those of ordinary skill in the art and the scope ofprotection for the invention is to be defined by the claims that follow.

The invention claimed is:
 1. A method of processing a hydrocarbon feedto remove undesired aromatic and non-aromatic organosulfur compoundscomprising: subjecting the hydrocarbon feed to a hydrotreating processto thereby lower the content of labile organosulfur compounds andproduce a hydrotreated effluent which contains refractory aromaticorganosulfur compounds; conveying the hydrotreated effluent and aneffective quantity of extraction solvent to an extraction zone toproduce an extract containing a major proportion of the aromatic contentof the hydrotreated effluent and a portion of the extraction solvent anda raffinate containing a major proportion of the non-aromatic content ofthe hydrotreated effluent and a portion of the extraction solvent;separating at least a substantial portion of the extraction solvent fromthe extract and retaining an aromatic-rich fraction; contacting thearomatic-rich fraction with an oxidizing agent and an oxidizing catalystto convert aromatic organosulfur compounds to oxides and produce anoxidized aromatic rich fraction; and separating the oxidizing agent andoxidizing catalyst from the oxidized aromatic-rich fraction, wherein theoxidizing agent is separated by solvent extraction.
 2. The method ofclaim 1, wherein the hydrocarbon feed further includes undesiredaromatic and non-aromatic organonitrogen compounds, the step ofsubjecting the hydrocarbon feed to a hydrotreating process also lowersthe content of labile organonitrogen compounds, and the step ofcontacting the aromatic-rich fraction with the oxidizing agent and theoxidizing catalyst also convert aromatic organonitrogen compounds tooxides.
 3. The method of claim 1, wherein the hydrotreating process isoperated at mild operating conditions.
 4. The method of claim 3, whereinthe hydrotreating process operates with a hydrogen partial pressure ofabout 10 bars to about 40 bars.
 5. The method of claim 3, wherein thehydrotreating process operates with a hydrogen partial pressure of about10 bars to about 30 bars.
 6. The method of claim 3, wherein thehydrotreating process operates with a hydrogen partial pressure of about20 bars.
 7. The method of claim 3, wherein the hydrotreating processoperates with an operating temperature of about 300° C. to about 400° C.8. The method of claim 3, wherein the hydrotreating process operateswith an operating temperature of about 300° C. to about 360° C.
 9. Themethod of claim 3, wherein hydrotreating process operates with anoperating temperature of about 300° C. to about 340° C.
 10. The methodof claim 3, wherein the hydrogen feed rate in the hydrotreating processstep is from about 100 liters of hydrogen per liter of oil to about 500liters of hydrogen per liter of oil.
 11. The method of claim 3, whereinthe hydrogen feed rate in the hydrotreating process step is from about100 liters of hydrogen per liter of oil to about 300 liters of hydrogenper liter of oil.
 12. The method of claim 3, wherein the hydrogen feedrate in the hydrotreating process step is from about 100 liters ofhydrogen per liter of oil to about 200 liters of hydrogen per liter ofoil.
 13. The method of claim 1, wherein the oxidizing agent is selectedfrom the group consisting of hydrogen peroxide, organic peroxides,oxides of nitrogen, oxygen, ozone, and air.
 14. The method of claim 1,wherein the oxidizing catalyst is selected from the group consisting ofhomogeneous catalysts and heterogeneous catalysts.
 15. The method ofclaim 14, wherein the oxidizing catalyst includes a metal from Group IVBto Group VIIIB of the Periodic Table.
 16. The method of claim 1, furthercomprising recovering a hydrotreated hydrocarbon product.
 17. The methodof claim 1, further comprising recovering a hydrocarbon productsubjected to oxidative desulfurization.
 18. The method of claim 1,further comprising combining the aromatic-lean raffinate and thearomatic-rich fraction that has been subjected to oxidation to provide areduced-organosulfur content hydrocarbon product.
 19. The method ofclaim 1, wherein the extraction solvent is selected from the groupconsisting of furfural, N-methyl-2-pyrrolidone, dimethylformamide anddimethylsulfoxide.
 20. The method of claim 1, wherein the extractionsolvent is provided in a solvent to oil ratio of 20:1.
 21. The method ofclaim 1, wherein the extraction solvent is provided in a solvent to oilratio of 4:1.
 22. The method of claim 1, wherein the extraction solventis provided in a solvent to oil ratio of 1:1.
 23. The method of claim 1,wherein the extraction zone operates at a temperature of about 20° C. toabout 120° C.
 24. The method of claim 1, wherein the extraction zoneoperates at a temperature of about 40° C. to about 80° C.
 25. The methodof claim 1, wherein the extraction zone operates at a pressure of about1 bar to about 10 bars.
 26. The method of claim 1, wherein theextraction zone operates at a pressure of about 1 bar to about 3 bars.